Swellable ball sealers

ABSTRACT

Swellable ball sealers comprising swellable material are described. A swellable ball sealer may be used as a diversion agent by being suspended in a fluid injected into a wellbore and swelling once seated on a perforation such that the swellable ball sealer adapts to the shape of a perforation opening on which the swellable ball sealer has seated.

FIELD

The subject disclosure generally relates to sealing perforations in a wellbore. More specifically, the subject disclosure relates to a method for selectively treating a plurality of formation intervals using swellable ball sealers.

BACKGROUND

It is a common practice in the petroleum industry to complete wells that have been drilled into the surface of the earth by placing into the well a cylindrical casing and cementing the casing into the well. The casing, and surrounding cement, provides fluid isolation between the well and the formation surrounding the well. To introduce fluid flow between the interior of the casing and the surrounding formation at desired locations in the well, the casing is perforated.

It may become desirable during the productive life of a reservoir to improve the fluid flow from the reservoir into the well through techniques collectively known as reservoir simulation. Two commonly used techniques are hydraulic fracturing and chemical stimulation.

In a trivial case, such as in a well in which only one zone has been perforated or in which treatment can be applied through all perforations, no zonal isolation is necessary. However, in wells with many perforations or multiple pay zones, it is often crucial to a successful reservoir stimulation operation to accurately and effectively isolate one zone for which treatment is to be applied from other zones where treatment is not to be applied. One reason for the need for effective zonal isolation is that treatment fluids, if applied equally to all perforations, are more likely to flow into zones with high permeability rather than into zones with poor permeability, i.e., the zones where permeability-improvement is desired. Therefore, it is desirable in such circumstances to divert the treatment fluid away from the high permeability zones, so the treatment, whether hydraulic or chemical, flows to the zones for which the treatment is desired.

Zonal isolation is achieved by employing a diversion technique. Various techniques for selectively treating multiple zones have been suggested including techniques using packers, wellbore plugs, setting bridge plugs, pumping ball sealers, pumping benzoic acid flakes and degradable particulates.

One of the more popular and widely used diverting techniques uses ball sealers. Ball sealers are, as the name suggests, spherical shaped objects which are meant to seal the perforations and prevent or inhibit fluid from within the wellbore from leaking through the perforation into the formation.

Ball sealers are typically introduced into the well at the surface and are carried down into the well with the treatment fluid. A positive pressure differential is maintained between the well and the formation surrounding the well. When a ball sealer encounters an open perforation with such a pressure differential, i.e., higher pressure in the well than in the formation, the ball sealer seats itself on the perforation and is held in place by the positive differential pressure.

Typical ball sealers consist of a rigid core usually constructed with a metal and enclosed with an elastomeric coating. It is desirable that the ball sealers produce an effective seal without being permanently lodged in the perforation or the formation. Therefore, ball sealers are advantageously sized so as to maximize their sealing potential without entering into the perforation. Ball sealers exist in a variety of diameters and densities to be applicable for different environments and to be size-appropriate for the entry holes the ball sealers are intended to seal.

The size of the ball sealer is typically selected based on the size of the perforation hole which will be plugged and is typically higher than the diameter of the hole. This enables partial penetration of the ball sealer into the perforation resulting in an effective plug. Self-adjustment of the elastomeric coating of the ball sealer to the shape of the perforation entrance provides additional seating strength and reduces penetration of the treating fluid into the plugged perforation hole during the treatment stage.

In certain situations the geometry of the perforation entry may vary. The shape of the perforation entry may deviate from the shape of an ideal cycle which is a preferred geometry type for plugging with ball sealers. This may occur in wells where perforations were extensively eroded during a fracturing treatment or during a production phase. In other situations, a coiled tubing mounted jetting tool may be used to create perforations in the casing which may also result in a non-ideal geometry of the holes. In these situations, it may be difficult to plug these perforations with conventional ball sealers as they will not be able to completely stop fluid penetration in the sealed zone. This may result in an ineffective diverting agent and in the case of a fracturing treatment it may result in an undesirable over displacement of propping agent into the near-wellbore zone.

In other situations, problems may arise due to the mechanical stability of the ball sealers at the perforation holes. This stability depends on a pressure difference across the casing. Lowering wellbore pressure due to a job, e.g., because of a temporary shut-down or reduction in the pumping rate may result in the unpredictable release of the ball sealers from the perforations thus opening the sealed zone.

The subject disclosure relates to ball sealers which adjust to the geometry of the surrounding environment. These ball sealers better adapt to different perforation shapes thereby providing better sealing. The resulting ball sealers will provide for better diversion.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In an embodiment, a ball sealer for plugging perforations in a wellbore is disclosed. The ball sealer comprises a swellable material configured to expand and produce a seal between an outer surface of a ball sealer and a surface of the perforation. Further, the swellable material is adapted to conform to the geometry of the perforation during swelling.

In other embodiments, methods of sealing a perforation in a wellbore are disclosed. The method comprises injecting into the wellbore a ball sealer suspended in a fluid to a region of the perforation wherein the ball sealer comprises a swellable material; applying pressure to fluid in the wellbore to seat the ball sealer on the perforation; exposing the swellable material to a triggering fluid; and allowing the ball sealer to swell and produce a seal between an outer surface of the seated ball sealer and a surface of the perforation.

In an embodiment, a system for injecting fluids into a formation is described. The system comprises a casing which includes a plurality of perforations and a plurality of ball sealers which are pumped into the casing with a fluid. Each ball sealer comprises a layer of swellable material which is adapted to conform to a geometry of the perforation during swelling. The swellable material forms a plug that inhibits fluid flow through the perforation.

Further features and advantages of the subject disclosure will become more readily apparent from the following detailed description when taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of embodiments of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings, and wherein:

FIG. 1 illustrates a typical deployment of ball sealers as a diversion agent into a wellbore;

FIG. 2 depicts a variation of the degree of cross-linking along the length of a sample for a uniform and a gradient elastomer;

FIG. 3 is a graph of the influence of temperature on swelling kinetics of EPDM elastomer in n-decane;

FIG. 4 illustrates the poor sealing between a spherical ball sealer and an oval perforation opening;

FIGS. 5A-5C illustrate examples of swellable ball sealers or perforation sealers. FIG. 5A illustrates a swellable perforation sealer, FIG. 5B illustrates a swellable perforation sealer at a perforation before swelling; and FIG. 5C illustrates the swellable ball sealer at a perforation after swelling; and

FIGS. 6A-6F illustrate various embodiments of sealing a perforation with a swellable ball sealer.

DETAILED DESCRIPTION

The particulars shown herein are by way of example and for purposes of illustrative discussion of the embodiments of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure. In this regard, no attempt is made to show structural details in more detail than is necessary for the fundamental understanding of the subject disclosure, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice. Furthermore, like reference numbers and designations in the various drawings indicate like elements.

The subject disclosure relates to swellable ball sealers comprising a coating of swellable material. Once introduced into a casing perforation these ball sealers will swell and conform to the geometry of the surrounding environment. As a result, the swellable ball sealers result in better diversion effectiveness enabling higher mechanical stability and reduced fluid penetration in the sealed zone.

In accordance with the subject disclosure, the swellable ball sealers may be injected into the wellbore by an appropriate method including injecting from the wellhead, or introducing the swellable ball sealers at an appropriate depth using coiled tubing, jointed tubing, and the like.

FIG. 1 illustrates a typical deployment of ball sealers as a diversion agent into a wellbore. The well (101) of FIG. 1 has a casing (113) extending for at least a portion of the length of the wellbore. Cement holds the casing (113) in place and isolates the penetrated formation. The cement sheath (117) extends upward from the bottom of the wellbore in the annulus between the outside of the casing (113) and the inside wall of the wellbore at least to a point above a producing zone (103). For the hydrocarbon in the production zone (103) to be produced, a fluid communication between the production zone (103) and the interior casing (113) is established. This is accomplished by perforations (111) made through the casing (113) and the cement sheath (117). These perforations (111) can be made using a perforating gun or other similar perforating tools as known to those skilled in art. The resulting perforations (111) form a flow path from the formation into the casing (113) or from the casing (113) into the formation.

The hydrocarbons flowing out of the production zone (103) through the perforations (111) and into the interior of the casing may be transported to the surface through a production tubing (115). An optional packer (109) can be installed near the lower end of the production tubing (115) and above the higher perforation (111) to achieve a pressure seal between the production tubing (115) and the casing (113), if necessary.

When diversion is needed during a well treatment, swellable ball sealers (107) in accordance with the subject disclosure may be used to seal some of the perforations. Sealing occurs when flow through a perforation (111) is significantly reduced as indicated by an increase in wellbore pressure as a swellable ball sealer (107) blocks off a perforation (111).

These swellable ball sealers (107) are generally spherical in shape, but other geometries may be used. Nonlimiting examples include sphere, egg shaped, pear shaped, capsular, ellipsoid, grandular, and the like. The swellable ball sealers (107) may be introduced into the casing (113) at a predetermined time during the treatment. The ball sealers (107) may be carried down the production tubing (115) or casing (113) by the treating fluid (105) flow. Once the treating fluid (105) arrives at the perforation zone in the casing, it flows outwardly through the perforations (111) and into the zone (103) being treated. The flow of the treating fluid (105) through the perforations (111) carries the swellable ball sealers (107) toward the perforations (111) causing the swellable ball sealers (107) to seat on the perforations (111).

Once seated on the perforations (111), ball sealers are held onto the perforations (111) by the fluid pressure differential which exists between the inside of the casing (113) and the production zone (103) on the outside of the casing (113). The swellable ball sealers (107) swell to a size which results in sealing the perforation when seated. The seated swellable ball sealers (107) serve to effectively close those perforations (111) until such time as the pressure differential is reversed, and the swellable ball sealers (107) are released. Other methods which will be discussed below may be used to release the swellable ball sealers (107).

Once the swellable ball sealers (107) reach a perforation, the swellable ball sealer (107) is designed to swell in response to either water and/or hydrocarbons so that swelling creates a seal. The swellable ball sealers (107) sets and increases in swelling which results in an adjustment of the shape of the swellable ball sealer (107) to the geometry of the perforation (111) and enhanced mechanical stability of the swellable ball sealer (107) compared to a typical non-swellable ball sealer. This effect is achieved due to the improved mechanical interlocking between the edges of the perforation and the swollen elastomer.

In other embodiments, swellable ball sealers are used which have a diameter before swelling which is less than the diameter of the perforation hole. In this situation, bridging and swelling of the ball sealers would take place either in the perforation tunnels or in the fracture zone lying in proximity to the perforation tunnels. Swelling of the diverting material in these zones provides complete isolation of the stimulated zone but at the same time there is no restriction on wellbore communication between the zones lying beyond the isolated region. The ball sealers in this instance are also not exposed to the abrasive effect of the treating fluid.

In an embodiment, the swellable ball sealers comprise a swellable material. The swellable material may be a swellable polymer or a swellable elastomer. As used herein the term “swellable material” includes any composition having elastomeric and swelling properties for the intended purpose of the oilfield element in question. For example, in some embodiments an elastomeric material may comprise substantially all elastomer, while in other formulations the elastomer may be accompanied by one or more other polymeric or non-polymeric compositions, such as thermoplastic and thermoset polymers, plasticizers, and the like. A swellable elastomer is an elastic material that swells when placed in certain fluids. Swelling is due to the absorption of the appropriate fluid, resulting in a volume increase. The fluid may include both water and oil-activated swellable elastomers and when these elastomers come into contact with the appropriate liquid, the elastomer swells to seal the available space.

Swellable materials may include organic water-swellable polymers, water swellable elastomers and inorganic water swelling compositions, e.g., clays. In an embodiment, the swellable material may include nitrile butadiene rubber (NBR), styrene butadiene rubber (SBR) based compositions, chlorobutadiene rubber based compositions, silicon rubber based compositions, carboxymethylcellulose and clays, natural rubber based compositions, and butadiene rubber compositions.

In an embodiment, swellable materials may be used which have the ability to degrade. Non-limiting examples include polyisoprene, ethylene propylene diene monomer (EPDM), ethylene acrylic, polymethylsiloxane, and hydrogenated nitrile rubber (HNBR), e.g., THERBAN®. In an embodiment, oil swellable materials which swell when in contact with oil may be used. These include neoprene rubber, natural rubber, nitrite rubber, hydrogenated nitrite rubber, acrylate butadiene rubber, poly acrylate rubber, butyl rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, styrene butadiene copolymer rubber, sulphonated polyethylene, ethylene acrylate rubber, epichlorohydrin ethylene oxide copolymer, ethylene-propylene-copolymer (peroxide cross-linked), ethylene-propylene-copolymer (sulphur cross-linked), ethylene-propylene-diene terpolymer rubber, ethylene vinyl acetate copolymer, fluoro rubbers, fluoro silicone rubber, silicone rubber, styrene-butadiene elastomer, styrene-butadiene-styrene elastomer, acrylonitrile-styrene-butadiene elastomer, ethylene-propylene-diene elastomer, alkylstyrene, polynorbornene, resin such as precrosslinked substituted vinyl acrylate copolymers, polymers of styrenes and substituted styrenes, polyvinyl chloride, copolymers of vinyl chloride, polymers and copolymers of vinylidene, acrylic polymers such as polymers of methylmethacrylate, ethyl acrylate; polymers containing alternating units of at least two polymers selected from styrene, pentadiene, cyclopentadiene, butylene, ethylene, isoprene, butadiene and propylene; diatomaceous earth, and mixtures of these materials. In an embodiment, the swelling process of the ball sealers may be controlled by modifying the chemical composition of the swellable module.

In an embodiment, the swellable materials may have a gradient crosslink density, i.e., composite materials where the crosslink density is locally varied so that a certain variation of the local material properties is achieved. Materials with gradient crosslink density are an example of functionally graded materials where the properties change gradually with position (B. Kieback, A. Neubrand, H. Riedel, “Processing techniques for functionally graded materials,” Materials Science and Engineering A362, 2003, 81). The property gradient in these materials is caused by a position-dependent chemical composition, microstructure or atomic order.

The Young's modulus, crosslink density, thermal expansion coefficient and other physical properties (e.g., swelling rate and swelling index) of such elastomers are continuously distributed within one sample in the definite direction, and do not contain any interfaces and distinct layers as depicted in FIG. 2. FIG. 2 depicts the variation of the degree of cross-linking along the length of a sample for the uniform (201) and gradient elastomers (203 and 205).

Different approaches may be used for generating gradient cross-link materials. In an embodiment, methods include controlling the degree of cross-link density by restricting the mobility of cross-linking reagents into the polymeric materials (1); by changing the structure of a cross-linking site and the nature of network nodes (2); 3D printing technology (3) and other methods as described in J. Stabik, A. Dybowska, “Methods of preparing polymeric gradient composites,” Journal of Achievements in Materials and Manufacturing Engineering, 2007, 25, 1, 67.

In other embodiments, multi-layered swellable materials comprising n individual layers of materials having various swelling characteristics may be utilized. In non-limiting examples, the swelling characteristic is greater in some layers than in other layers of the multi-layered swellable material. In other embodiments, some layers may have a lower rate of diffusion and swelling than some other layers. Further examples of these multi-layered materials may be found in co-owned United States Publication No.: US20110120733, entitled “Functionally graded swellable packers,” filed Nov. 20, 2009, the contents of which are herein incorporated by reference.

In other embodiments, gradient swellable materials may be utilized; the composition and properties of these gradient swellable materials may vary spatially in a controlled way. In graded materials, the elasticity modulus, the hardness, or the swelling index may gradually change over the range of a sample which contains no boundary, layers, etc.

In an embodiment, the swelling process of the ball sealers may be controlled by covering the ball sealer with a degradable or a semipermeable coating. The coating may be degradable or non-degradable. Degradable coatings can be used to stop or delay the premature swelling of the ball sealer during entry into a wellbore. The outer layer delays the swelling of the ball sealer due to the low permeability of the coating. However, if the coating is non-degradable, the swelling kinetics will be controlled by diffusion of a solvent (oil, brine) through the membrane. The degradation mechanism of the coating may be dissolution in fracturing fluids, oil or brine, temperature decomposition, biodegradation, swelling, corrosion and/or erosion controlled.

In an embodiment, the swelling process of the ball sealers may be constrained by controlling the composition of the fluid surrounding the ball sealers, in non-limiting examples, by controlling the ratio of water to hydrocarbon or vice versa, the pH of the composition of the fluid, or the ion concentration of the fluid.

In an embodiment, the swelling process of the ball sealers may be activated using an increase in temperature. EPDM rubber (0.5 in diameter) samples were tested at various temperatures to determine the effect of temperature on swelling. FIG. 3 shows the variation of swelling index with time for ball-shaped EPDM rubber in n-decane. It is clear from the graphs that more swelling occurs when samples are kept in a hot solvent. Similar to other materials, elastomers expand more with increasing temperature due to increased diffusion. Maximum swelling occurs for these elastomers at a temperature of 100° C.

FIG. 4 is an illustration of the poor sealing between a spherical ball sealer 405 and an oval perforation opening 401. The spherical ball sealer 405 fails to close the gaps 403 because the shape of the spherical ball sealer 405 is not compatible with the shape of the opening 401. A similar problem occurs when the perforation charge fails to produce a regular shaped perforation opening. A spherical ball sealer in this instance would also fail to close the gaps because of the incompatible shapes of the ball sealer and the imperfectly shaped perforation opening.

FIG. 5A-5C illustrates examples of a swellable ball sealer or perforation sealer. FIG. 5A is a cross-section of a swellable perforation sealer 501. The swellable perforation sealer 501 has an inner rigid core 505 and an outer layer of a swellable material 503. For example, the inner rigid core may comprise a metal. The swellable material 503 is able to swell and deform allowing the ball sealer to adapt to irregular shapes of perforation openings. FIG. 5B illustrates the swellable perforation sealer 501 at a perforation in a casing 507 before swelling and FIG. 5C illustrates the swellable ball sealer 501 at a perforation in the casing 507 after swelling. The swellable ball sealer swells inside the perforation hole and partially penetrates into a perforation tunnel in the casing 507.

FIGS. 6A-6F illustrates various embodiments of sealing a perforation with a swellable ball sealer. FIG. 6A depicts a swellable ball sealer 605 without a core at a perforation in a casing 601 before swelling. FIG. 6B illustrates the swellable ball sealer 605 at a perforation in a casing 601 after swelling. As the swellable ball sealer 605 has no core, this means the entire body of the ball sealer 605 is swellable. FIG. 6C illustrates a swellable ball sealer 607 comprising a hard/rigid core 609 and a swellable layer 611 which is non-deformable before swelling and FIG. 6D illustrates the swellable ball sealer 607 at a perforation in a casing 601 after swelling. Finally, FIG. 6E illustrates a swellable ball sealer 617 with a rigid core 613 and a deformable swellable layer 615 at a perforation in a casing 601 before swelling. FIG. 6F illustrates the swellable ball sealer 617 at a perforation in a casing 601 after swelling.

In an embodiment, swellable ball sealers may be unseated using a number of different methods. Post treatment removal of the swellable ball sealers may be accomplished with a negative pressure drawdown across the sealed zone similar to removal of the typical ball sealers. This creates a force which drives the ball sealers out of the perforation. This method may not provide satisfactory results if the ball sealer is located deep inside the perforation tunnel and friction with the perforation tunnel walls is substantial. In this situation, preliminary reduction of the size of the ball sealers may be an option.

In other embodiments, the swellable ball sealers may be removed by shrinkage of the ball sealers, partial degradation of the ball sealers, dissolution of the ball sealers, or melting of the ball sealers. Shrinkage of the swellable ball sealers may be initiated by altering the composition of the surrounding fluid, in non-limiting examples, altering the surrounding fluid from water to hydrocarbon or vice versa, altering fluid pH or altering the ionic strength and concentration of ions in the surrounding fluid.

In other embodiments, partial or full destruction of the ball sealers will establish communication between sealed zones and the wellbore. This may be achieved through degradation of the ball sealer material(s) under bottomhole conditions or reaction of the material(s) with chemical agent(s) in the fluid. Non-limiting examples include oxidizers or hydrolyzing agents, e.g., acids or bases.

In other embodiments, swellable materials may be destroyed by temperature, e.g., borate cross-linked guar.

Removal of the sealing material may also be accomplished through dissolution of at least one of the components of the ball sealer. Materials which dissolve in water include water soluble polymers, water soluble elastomers, carbonic acids, rock salt, amines and inorganic salts. Materials which dissolve in oil include oil soluble polymers, oil soluble resins, oil soluble elastomers, polyethylene, carbonic acids, amines, or waxes.

Removal of the sealing material may also be accomplished with melting-assisted ball sealer removal. At least one component of the ball sealer may be constructed from material that has a melting point in a specified temperature range. When the wellbore environment temperature is increased above the melting point the shape of the ball sealer changes resulting in a loosening of the ball sealers' sealing properties. This heating may occur after wellbore treatment as a result of post-job temperature recovery in the reservoir. In other embodiments, the heating may be initiated by artificially heating the isolated zone. This may be accomplished by introducing heated gas or fluid in the zone, injecting chemical systems which provide heating through chemical reaction(s) or by using downhole wellbore heaters. Meltable or fusible material used in ball sealers may be soluble in a wellbore/formation fluid. Examples of meltable or fusible materials include waxes, paraffins, saturated hydrocarbons with the number of hydrocarbons greater than 30, tin, lead, bismuth and their alloys and their composite/blends with filler materials, e.g., sand minerals, etc.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function. 

What is claimed is:
 1. A ball sealer for plugging perforations in a wellbore, the ball sealer comprising: a swellable material configured to expand and produce a seal between an outer surface of a ball sealer and a surface of the perforation; and wherein the swellable material conforms to a geometry of the perforation during swelling to produce the seal.
 2. The ball sealer of claim 1, wherein the swellable material swells upon exposure to downhole fluids.
 3. The ball sealer of claim 1, wherein an initial diameter of the ball sealer is less than a diameter of the perforation.
 4. The ball sealer of claim 1, wherein the swellable material degrades in response to conditions in the wellbore.
 5. The ball sealer of claim 1, wherein the swellable material degrades in response to contact with a particular fluid in the wellbore.
 6. The ball sealer of claim 1, further comprising a semipermeable coating, surrounding the swellable material.
 7. The ball sealer of claim 1, further comprising a degradable coating, surrounding the swellable material.
 8. The ball sealer of claim 1, further comprising an inner rigid core surrounded by an outer layer of the swellable material.
 9. The ball sealer of claim 1, wherein the swellable material is a swellable polymer or a swellable elastomer or both.
 10. The ball sealer of claim 9, wherein the swellable elastomer comprises an oil swellable elastomer.
 11. The ball sealer of claim 1, wherein the swellable material comprises a water-swellable material.
 12. A method of sealing a perforation in a wellbore comprising: injecting into the wellbore a ball sealer suspended in a fluid to a region of the perforation, wherein the ball sealer comprises a swellable material; applying pressure in the wellbore to seat the ball sealer on the perforation; exposing the swellable material to a triggering fluid; and allowing the ball sealer to swell and produce a seal between an outer surface of the seated ball sealer and a surface of perforation.
 13. The method of claim 12, wherein the swellable material is capable of swelling in oil and/or in water.
 14. The method of claim 12, further comprising: introducing ball sealers in the fluid in an amount sufficient to plug perforations in the wellbore adjacent to a first zone; and applying pressure in an amount sufficient to fracture a formation in an area adjacent to the first zone which causes the ball sealers to seal off perforations in the first zone and direct the fluid into a second zone of the wellbore thereby fracturing the formation adjacent to the second zone.
 15. The method of claim 12, wherein the swellable material comprises a deformable swellable layer.
 16. A system for injecting fluids into a formation, the system comprising: a casing which includes a plurality of perforations; a plurality of ball sealers which are pumped into the casing with a fluid, wherein the ball sealers comprise: a layer of swellable material which is adapted to conform to a geometry of the perforation during swelling; and forming a plug with one or a plurality of the ball sealers that inhibits fluid flow through the perforation.
 17. The system of claim 16, wherein the swellable material comprises an elastomer operable to swell upon exposure to a hydrocarbon fluid.
 18. The system of claim 16, wherein the swellable material is operable to increase in volume on exposure to a triggering fluid.
 19. The system of claim 16, wherein the swellable material comprises segments having different cross link densities.
 20. The system of claim 16, further comprising a multilayered swellable material comprising layers of swellable material wherein each layer has a different swelling characteristic. 